Method for Exhaust Waste Energy Recovery at the Reciprocating Gas Engine-based Polygeneration Plant

ABSTRACT

A method for exhaust waste energy recovery at the reciprocating gas engine-based polygeneration plant which includes supplying this plant with any on-site available methaneous gas, converting from 15 to 30% of supplied gas into electric or mechanical power and producing a liquefied methaneous gas (LMG) co-product from the other 85-70% of supplied gas, and thereby obviates a need for any specialized refrigeration equipment, refrigerants and fuel for LMG co-production at a rate of 0.4-0.6 ton/h for each MW of engine output and makes possible to increase the LMG co-production rate up to 0.9-1.1 t/MWh at the sacrifice of a fuel self-consumption minimized down to 1-2% of the amount of gas intended for liquefaction.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefits of U.S. Provisional Application No.62/771,603 filed on Nov. 272018.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable

REFERENCE TO SEQUENCE LISTING, A TABLE, OR A COMPUTER PROGRAM LISTINGCOMPACT DISK APPENDIX

Not Applicable

FIELD OF INVENTION

The present invention relates to the field of energy conversiontechnique, and more specifically to the methods enabling theintroduction of a new class of the polygeneration technologies intended,as known, for high-efficient and low carbon emitting simultaneousco-production of power and two or more energy outputs (heat, cold, CO₂,etc.) from one energy input (generally fossil or renewable fuel). Moreparticularly, the present invention relates to the methods makingpossible to profitably combine the operation of the reciprocating gasengine-based power plant with co-production of liquefied methaneous gas(natural gas, biogas, landfill gas, coalbed methane, renewable gas) at asacrifice of better recovery of exhaust waste energy of such plant.

BACKGROUND OF THE INVENTION

Recovering the exhaust waste energy of the power plants based on theturbocharged reciprocating gas engine prime movers is well known andmuch used method for increase in total fuel-to-useful energy conversionefficiency through co-production of an additional power in so-calledbottoming cycles and/or through harnessing this waste energy forheating, cooling and other purposes. At the same time, it should bestressed that an exhaust waste energy potential of turbochargedreciprocating gas engine, as a more efficient heat engine, is markedlylower in comparison with gas turbine and any improvements in recoveringthis potential involve the significant difficulties.

The most widespread method for recovering the waste energy of theexhaust gases escaped the cylinders of turbocharged reciprocating gasengine at the enhanced pressure and temperature comprises the followingprocesses: a) recovering a kinetic and a part of thermal energy ofexhaust gases in the gas turbine of turbocharger for driving thecompressor of this turbocharger; b) use of this compressor for supplyingthe gas engine with pressurized combustion air; c) further recoveringthe most of thermal energy of the exhaust gases at atmospheric pressurein waste heat recovery boiler installed downstream of the gas turbine ofturbocharger for producing the steam; d) using the steam by the steamturbine of bottoming cycle for producing an additional power or by theindustrial customer for process purposes; and e) removing the exhaustgases from the outlet of waste heat recovery boiler into atmosphere at atemperature exceeding a temperature of surroundings by at least 70-90°C.

The main difficulties in using this method are the low capacity and notsufficiently high pressure and temperature of steam produced by thewaste heat recovery boiler. Eventually this leads to a small poweroutput of the steam bottoming cycle and its high specific installedcosts or to impossibility for using the steam with low parameters inmany industrial processes. In addition, a waste heat recovery boiler ischaracterized by the large specific values (m {circumflex over( )}2/kWth) of its heat-exchange surfaces, due to the relatively lowspeeds of exhaust gases and a moderate difference in exhaust gasestemperature and water in this boiler. All mentioned problems inrecovering the exhaust gas energy are resulting from the advantages ofreciprocating engine, as the most efficient heat engine, namely amoderate combustion specific air flow-rate (kg/kWh) and a relatively lowtemperature of exhaust gases at the inlet of said waste heat recoveryboiler.

All technical solutions proposed to improve the described method forrecovering the waste energy of the engine exhaust gases may be dividedinto two groups. The solutions of the first group are described in thepublished patents and patent applications EP0715058, EP1674681,WO2008/135059, et al. General idea combining all technical solutions ofthe first group consists in an increase in exhaust gas temperature atthe inlet of waste heat recovery boiler through combusting an additionalfuel in the duct burner installed directly upstream of the boiler or inthe stream of hot pressurized exhaust gases escaped the engine cylindersupstream of the turbocharger's turbine. The latter approach is morethermodynamically efficient, since it makes possible to increase notonly a power of the steam bottoming cycle, but a power of turbocharger'sturbine as well. However, the economically justified applications ofsupplementary firing upstream of turbocharger's turbine are limited by amaximum admissible temperature of 650-700° C. at the turbine inlet,otherwise a specially designed and much more expensive gas turbine withcooled blades should be used. In addition, in both mentioned cases thereduction in specific values of boiler heat-exchange surfaces isrelatively small, since such boiler is as before operated at the exhaustgases pressure close to atmospheric level.

The solutions of the second group are described in the published patentapplications GB1539166, WO 9428298, WO2007/115579, et al. General ideacombining all technical solutions of the second group consists in thearrangement of waste heat recovery boiler at the outlet of the enginecylinders in the area of a high temperature and an enhanced pressure ofexhaust gases escaped the said cylinders. In this case theturbocharger's turbine is placed downstream of the boiler in the area ofthe significantly reduced temperature of exhaust gases escaped the saidboiler. The described changes in conventional configuration of theexhaust waste energy recovering system make possible to drasticallyincrease the pressure, temperature and flow-rate of steam generated bythe waste heat recovery boiler, markedly reduce the specific values ofits heat-exchange surfaces and almost double the bottoming cycle poweroutput. However, a temperature of exhaust gases at the inlet of exhaustgas turbine proves to be significantly reduced, resulting in decreasingits power output down to a level insufficient to supply the charging aircompressor with a full amount of power required for its driving. Inthese cases, a part of steam bottoming cycle power output may be used tocompensate a deficiency in power for compressor driving. However, in anycase the remainder of the increased steam bottoming cycle outputprovides a significant increase in total plant output and its enhancedefficiency.

As a whole, the technical solutions of both groups can markedly improvethe performance of the reciprocating gas engine-based combined cycle orcogeneration plants. However, they are not intended for generation ofany new co-product at such plants and do not extend their applicability,which is the main purpose of the invented method. As this co-product,the liquefied methaneous gas (LMG) generated in the small-scale volumesat a sacrifice of exhaust waste energy of reciprocating gas engine-basedpolygeneration plant was chosen. In so doing, the followingconsiderations have been taken into account: a) a wide spectrum of themethaneous gases (pipeline natural gas, biogas, landfill gas, coal-bedmethane and renewable gas) which may be locally available forliquefaction; b) operation of gas engine(s) on the same fuel which isintended to be liquefied at the plant; c) possibility for creation ofthe on-site LMG storages, providing the supply of the same or co-locatedpeaking power plant with stored fuel during periods of high-demand forpower and gas from the networks; d) availability of the promising andrising markets for LMG products; and e) a high profit which may beobtained from a cheap LMG co-production at the gas engine polygenerationplants through recovering their exhaust waste energy. Such LMGco-production could replace a small-scale LMG production at thespecialized plants which is characterized by a very high energyintensity and performed with use of the costly refrigeration equipmentand refrigerants. It was found that at the reciprocating gasengine-based polygeneration plants the exhaust gases of a prime movermay be converted into an effective refrigerant, whereas a recovery oftheir cold thermal energy may eliminate or minimize a need for energy inthe LMG production.

The use of the power plant exhaust gases for co-producing the liquefiednatural gas (LNG) is described in the U.S. Pat. No. 9,618,261, asapplied to the gas turbine-based power plant. However, the used approachcannot be applied to the reciprocating gas engine-based power plantowing to the distinctions between the working principles of gas turbineand gas engine. In addition, according to the proposed technicalsolution, the gas turbine exhaust gases should contain only nitrogen,carbon dioxide and water vapor. For these purposes, a gas turbine shouldbe converted from operation on an open Brayton cycle into operation on asemi-closed Brayton cycle using exhaust gas recirculation (EGR) at asubstantially stoichiometrically balanced conditions. Up to now this isa stubborn technical problem, which is additionally complicated by aneed for decarbonization of gas turbine exhaust. By this means for theco-production of LNG at the reciprocating gas engine-based power plantsa new method of converting the exhaust gases into an effectiverefrigerant should be elaborated.

This can be made using the general ideas underlying the technicalsolutions of both groups described above. However, practical realizationof these ideas calls for a new approach and the novel technicalsolutions. In particular, a placement of exhaust gas turbine downstreamof waste heat recovery boiler, as it is proposed in the patentapplication WO2007/115579, does not provide reduction in temperature ofexhaust gases escaped the turbine below −25÷−40° C. At the same time, touse these gases as refrigerant for methaneous gas liquefaction, theturbine outlet temperature should be below at least −90÷−100° C. On theother hand, a possible usage of supplementary firing before the wasteheat recovery boiler arranged at the outlet of engine cylinders callsfor placement of duct burner in the stream of hot pressurized exhaustgases, contrary to its arrangement in the stream of non-pressurizedexhaust gases, proposed in the patent application EP1674681.

As a whole, the method for exhaust waste energy recovery at thereciprocating gas engine-based polygeneration plants is selected as asubject for the improvement in the present invention. Thereby, far morecomplete harnessing the thermal energy of exhaust gases and aninnovative recovering their kinetic energy being used for co-productionof power and on-site liquefaction of methaneous gas are found to be theproper ways for achievement of the invention's goals.

SUMMARY OF THE INVENTION

In one or more embodiments, a proposed method for an exhaust wasteenergy recovery at a reciprocating gas engine-based polygeneration plantmay comprise in combination: a) supplying said polygeneration plant witha methaneous gas selected from a group consisting of pipeline naturalgas, biogas, landfill gas, coal-bed methane and renewable methane andused as a fuel in said gas engine; b) supplying the gas engine with acharging air pressurized by an air compressor and cooled upstream of thegas engine; c) burning a mixture of the fuel and the charging air in thegas engine with producing a gas engine power output, as a main productof the polygeneration plant, and releasing a pressurized exhaust gasstream comprising a mixture of nitrogen, oxygen, carbon dioxide andwater vapor at a high temperature; d) harnessing most of a hot thermalenergy of the pressurized exhaust gas for production of a process steamin a waste heat recovery boiler installed at an outlet of the gasengine; e) using the process steam for production of a power output of asteam bottoming cycle; f) expanding the pressurized exhaust gas in a gasturbine installed downstream of said waste heat recovery boiler,resulting in recovering a kinetic energy and a remainder of a thermalenergy of the pressurized exhaust gas for production of a power outputof said gas turbine; and g) using at least a part of the power output ofsaid gas turbine and said steam bottoming cycle for driving said aircompressor.

In so doing, the method may additionally comprise: a) supplying thepolygeneration plant with said methaneous gas at a rate exceeding anamount of said fuel used by the gas engine; b) forming a pre-treatedmethaneous gas stream through drying and purifying a supplied methaneousgas as needed to meet a pre-treatment quality standard set up for themethaneous gas being liquefied; c) compressing the pre-treatedmethaneous gas up to a high pressure of at least 60 barA by a methaneousgas compressor if necessary, resulting in forming a high-pressuremethaneous gas stream; d) pre-cooling said high-pressure methaneous gasso, forming a pre-cooled high-pressure methaneous gas stream; e)reducing in temperature of the pressurized exhaust gas escaped the wasteheat recovery boiler to a near ambient value with accompanied drainageof a formed condensate; f) a drying of the pressurized exhaust gas and afollowing pre-cooling of a dried pressurized exhaust gas to atemperature below 0° C. in a cold regenerator so, forming a dried andpre-cooled pressurized exhaust gas stream upstream of said gas turbine;g) said expanding the dried and pre-cooled pressurized exhaust gas inthe gas turbine, resulting in producing the power by said gas turbineand forming a deeply cooled non-pressurized exhaust gas stream escapedthe gas turbine; h) recovering a cold thermal energy of said deeplycooled non-pressurized exhaust gas first for a liquefying of the wholeof said pre-cooled high-pressure methaneous gas in a gas liquefier andthen for said pre-cooling of the dried pressurized exhaust gas in saidcold regenerator; i) using a non-pressurized exhaust gas removed fromthe cold regenerator to an atmosphere for removing a water vaporcaptured during said drying of the pressurized exhaust gas; j)depressurizing a high-pressure liquefied methaneous gas escaped the saidgas liquefier down to a selected low pressure, resulting in forming alow-pressure two-phase liquefied methaneous gas stream; k) separatingsaid low-pressure two-phase liquefied methaneous gas stream, resultingin forming a low-pressure methaneous vapor stream and a low-pressureliquefied methaneous gas stream; l) using said low-pressure methaneousvapor as the fuel for the gas engine; m) using said low-pressureliquefied methaneous gas as a co-product of the polygeneration plant;and n) using a part of the power outputs of the gas turbine and thesteam bottoming cycle for driving said methaneous gas compressor.

In one or more embodiments, said depressurizing the high-pressureliquefied methaneous gas may be performed sequentially first in awork-performing liquefied methaneous gas expander so that amedium-pressure liquefied methaneous gas is formed and then in aJoule-Thompson valve.

In one or more embodiments, a cold thermal energy of the low-pressuremethaneous vapor may be recovered first for subcooling saidmedium-pressure liquefied methaneous gas upstream of the Joule-Thompsonvalve, and then for said pre-cooling of the high-pressure methaneous gasupstream of said gas liquefier.

In one or more embodiments, a pressure of the low-pressure methaneousvapor upstream of the gas engine may be provided at a level exceeding apressure of the charging air through said selecting of the low pressureof said two-phase liquefied methaneous gas stream or/and compressing thelow-pressure methaneous vapor if necessary.

In one or more embodiments, said drying of the pressurized exhaust gasmay be performed by a pressure swing adsorber, wherein saidnon-pressurized exhaust gas outgoing from the cold regenerator is usedfor purging a regenerated bed of said pressure swing adsorber.

In one or more embodiments, removing the non-pressurized exhaust gasfrom the pressure swing adsorber to the atmosphere may be performed byan exhaust fan consuming a part of the power outputs of the gas turbineand the steam bottoming cycle.

In one or more embodiments, an enhanced yield of the polygenerationplant co-product may be achieved through an increase in a pressure ofthe high-pressure methaneous gas at an outlet of the methaneous gascompressor up to a value exceeding 60 barA.

In one or more embodiments, an enhanced yield of the polygenerationplant co-product at a given pressure of the charging air may be achievedthrough an increase in a pressure of the dried and pre-cooledpressurized exhaust gas at an inlet of the gas turbine, resulting inproducing an extra power output by said gas turbine and in additionalreducing a temperature of the deeply cooled non-pressurized exhaust gasstream escaped the gas turbine.

In one or more embodiments, said increase in the pressure of the driedand pre-cooled pressurized exhaust gas may be performed with use of anexhaust gas compressor installed upstream of the pressure swing adsorberand equipped with an aftercooler.

In one or more embodiments, an extra power output of the steam bottomingcycle may be provided through supplementary firing an additional fuel inthe stream of the pressurized exhaust gas ahead of the waste heatrecovery boiler.

In one or more embodiments, said extra power outputs of the steambottoming cycle and the gas turbine may be consumed for driving saidexhaust gas compressor and for serving the needs of the methaneous gascompressor for a higher power input.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments will hereinafter be described in detail below with referenceto the accompanying drawings, wherein lie reference numerals representlike elements. The accompanying drawings have not necessarily been drawnto scale. Where applicable, some features may not be illustrated toassist in the description of underlying features.

FIG. 1 is a schematic view of the first embodiment of the reciprocatinggas engine-based polygeneration (GPG) plant using the invented method ofexhaust waste energy recovery for co-production of power and liquefiedmethaneous gas (LMG).

FIG. 2 is a schematic view of the second embodiment of the GPG plantusing the invented method of exhaust waste energy recovery forco-production of LMG.

FIG. 3 is a diagram, showing an impact of charging air pressure on theLNG capacity and electric and re-counted outputs and efficiencies of GPGplant, according to the present invention.

FIG. 4 is a diagram, showing an impact of the GPG plant configurationson amount of fuel self-consumed for LNG co-production, according to thepresent invention.

FIG. 5 is a diagram, showing an impact of the GPG plant configurationson specific LNG capacity and a share of NG liquefied, to the presentinvention.

FIG. 6 is a diagram, showing an impact of the GPG plant configurationson LNG capacity and total plant efficiency, according to the presentinvention.

FIG. 7 is a diagram, showing an impact of the proposed method on anextra LNG production at the small-scale LNG plants, according to thepresent invention.

DETAILED DESCRIPTION OF THE INVENTION

The practical realization of the proposed method for exhaust wasteenergy recovery at the reciprocating gas engine-based polygeneration(GPG) plant may be performed through an innovative use of gas engineexhaust for liquefying most of the methaneous gaseous fuel (pipelinenatural gas, biogas, landfill gas, coal-bed methane and renewablemethane) delivered into such plant. By this means the GPG plant may beused for co-production of power and liquefied methaneous gas (LMG); inso doing on-site liquefaction of methaneous gas at the GPG plant in thewide range of LMG co-product pressure is distinguished from LMGproduction at the specialized small-scale plants by much greatersimplicity of the proposed process and its much higher efficiency.Taking into account that the energy and pre-treatment costs areparticularly high at the small-scale LMG plants and that the inventedmethod may drastically reduce these costs, it may be especiallypromising for co-production of the LMG at a rate up to 1.10 t/h per eachMW of the GPG plant electric output.

The FIG. 1 is a schematic view of the first embodiment of GPG plantusing the invented method of exhaust waste energy recovery forco-production of power and LMG in the simplest plant configurationwithout consumption of any additional fuel or power. Here the involvedequipment packages are designed as 100—supercharged reciprocating gasengine package in the standard configuration but without turbocharger,200—steam bottoming cycle package, 300—terminal exhaust energy recoverypackage, and 400—methaneous gas liquefaction package. The interaction ofthe equipment in all mentioned packages goes on as follows.

The basic gas engine 101 of package 100 is supplied with charging airvia pipe 107. This air is captured from atmosphere via pipe 103,pressurized by air compressor 104 driven by a motor 105 and cooled in inthe air cooler 106. The gas engine 101 is also supplied via pipe 102with methaneous gaseous fuel, which is delivered either fromliquefaction package 400 via pipe 415 or directly from the pipeline 401via pipe 402. The mechanical work done by gas engine 101 is convertedinto electrical power by generator 108, whereas the pressurized exhaustgases escape the engine cylinders at a high temperature of 500-550° C.via pipe 109.

A high-temperature part of exhaust thermal energy is converted intomechanical power in the steam bottoming cycle package 200. Here acooling of pressurized exhaust gases is performed in the small-sized onepressure level waste heat recovery boiler 201, resulting in generationof high-pressure superheated steam at the outlet of this boiler. Thesteam is delivered via pipe 206 into condensing steam turbine 207,wherein steam expansion leads to performing a mechanical work by thisturbine coupled with an electric generator 208. The exhaust steam isdirected via pipe 209 to the water or air-cooled condenser 202, fromwhere condensate is delivered by high-pressure pump 203 via pipe 204into cooler 106. Here a compression heat of charging air is used topreheat the circulated water upstream of waste heat recovery boiler 201,where the preheated water is directed via pipe 205.

The terminal exhaust energy recovery package 300 is intended forconverting the exhaust gases into an effective refrigerant and for useof this refrigerant in the process of liquefaction of suppliedmethaneous gas. For these purposes, the exhaust gases escaped the boiler201 are first directed via pipe 210 to the heat exchanger 301, whereinthey are cooled down to a near ambient temperature with accompanieddrainage of condensate (LH₂O) formed. The extracted heat is dissipatedinto surroundings or/and used for heating purposes. A recovered heatbecomes the third co-product of GPG plant, increasing significantly theplant total fuel efficiency.

In any case the pressurized exhaust gases with water vapor content notexceed 0.5-0.7% (m/m) are directed via pipe 302 to the working chamberof a standard two-chamber pressure swing adcorber (PSA) 303, wherein thegases are cleaned from the water vapor components. The cleaned andpressurized exhaust gases are further subjected to a pre-cooling down to−40÷−50° C. in the cold regenerator 304 and directed via pipe 305 to thegas turbine (work-performing low-pressure expander) 306.

The pressurized, pre-cooled and cleaned exhaust gases are expanded inthis gas turbine coupled with generator 307, wherein mechanical work ofturbine is converted into electric power. The expansion of exhaust gasesis accompanied by their deep cooling significantly below −100° C., atwhich the formation of solid CO₂ (dry ice) in the stream ofnon-pressurized exhaust gases escaped the turbine 306 is howeverexcluded. At the same time, a cold thermal energy of thesenon-pressurized gases is large enough to use them as refrigerant forliquefaction of a pressurized methaneous gas in the gas liquefier 309installed downstream of the turbine 306.

The rest of a cold thermal energy of the non-pressurized exhaust gasesescaped the gas liquefier 309 is recovered in the cold regenerator 304,where these gases are directed via pipe 310. Here this cold thermalenergy is used for said pre-cooling of the pressurized exhaust gasesupstream of the gas turbine 306. The non-pressurized exhaust gasesoutgoing from the cold regenerator 304 are used for purging the sorbentbed of the second chamber of the PSA unit 303 which is in regenerationoperation mode. An electrically-driven exhaust fan 311 is optionallyused for removing the non-pressurized exhaust gases from the PSA device303 into atmosphere via pipe 312.

The GPG plant is supplied with a methaneous gas (MG) from the pipeline401 with its delivering into gas engine 101 via a pipe 402 during plantstart-up and via a pipe 414 during operation of the plant. A pressure ofsupplied gas in the pipe 402 exceeds usually a pressure of the chargingair in the pipe 107 at the gas engine inlet, whereas in the pipe 414 thementioned fuel pressure is maintained as result of operating theequipment in the package 400. During plant operation all delivered MG isdirected via pipe 403 to a pre-treatment unit 404, wherein the MG issubjected to dehydration and cleaning from CO₂, aromatic and paraffinhydrocarbons. If a pressure of supplied MG is below 60 barA, a cleanedgas is further compressed up to 60-80 barA in the MG compressor 405driven by a motor 406. A temperature of this cleaned and high-pressure(HP) MG is further reduced in the conventional gas cooler 407 down to avalue close to a temperature of atmospheric air. Following pre-coolingthe HP cleaned MG prior to the gas liquefier 309 is performed in thecold vapor recuperator 408, resulting in reducing a gas temperaturebelow 0° C. At this temperature the cleaned and pre-cooled HP MG isdirected to the gas liquefier 309, wherein full gas liquefaction isperformed through recovering a cold thermal energy of the deeply coolednon-pressurized exhaust gas. The HP liquefied methaneous gas (HP-LMG)outgoing from liquefier 309 is further reduced in pressure first in thework-performing liquefied gas expander 409, then subcooled in the heatexchanger 410 and finally depressurized down to a selected low pressure(LP) in the Joule-Thompson valve 411. A liquefied two-phase LP streamoutgoing from the JTV device is separated in the gas separator 412 intoa gas vapor stream 413 used as fuel for the gas engine 101 and a stream415 recovered as LP-LMG co-product of the GPG plant. A cold thermalenergy of the gas vapor stream 413 is recovered first in the heatexchanger 410 for said subcooling purposes and then in the cold vaporrecuperator 408 for said pre-cooling purposes. If the selected lowpressure of the LP-LMG co-product is below a pressure of the chargingair in the pipe 107 at the gas engine inlet, a fuel compressor installedin the pipe 414 (not shown) is used to provide a required fuel pressureat the engine inlet.

A total power output of the steam turbine 207, gas turbine 306 andliquefied gas expander 409 is sufficient to meet the plant power demandsfor driving the air compressor 104, water pump 203, exhaust fan 311 andgas compressor 405. This makes possible to supply a grid with a poweroutput of the gas engine 101 designed by a manufacturer for itsoperation in the simple cycle operation mode and simultaneously toco-produce 0.4-0.6 t/h of the LP-LMG per each MW of the engine poweroutput. In so doing, any consumption of an additional fuel for thementioned purposes is obviated.

FIG. 2 is a schematic view of the second embodiment of the GPG plantusing the invented method of exhaust waste energy recovery forco-production of LMG. It makes possible to increase a LP-LMGco-production capacity by a factor of 2-2.5 without changes in designand parameters of the gas engine selected for installation in the firstembodiment of the GPG plant. In so doing, an enhancement in LP-LMGco-production rate may be achieved through using any one or combinationof two following methods: a) a further increase in pressure of the HPpre-cooled MG at the inlet of gas liquefier 309, resulting from acorresponding enhancement in gas pressure at the outlet of MG compressor405; and b) a further reduction in temperature of the deeply coolednon-pressurized exhaust gas at the inlet of said gas liquefier 309,resulting from a higher pressure drop in the gas turbine 306 and callingfor a correspondingly higher pressure of the pre-cooled pressurizedexhaust gas at the inlet of said gas turbine. The latter approach may berealized through an additional compression of the pressurized exhaustgas escaped the waste heat recovery boiler 201 by an exhaust gascompressor 314 driven by a motor 315 and equipped with an aftercooler316 and a condensate drainage device. In so doing, an enhancement inpower output of the gas turbine 306 may be used to partially compensatefor a power required for driving the exhaust gas compressor 314, whereasremoving the non-pressurized exhaust gas from the PSA device 303 intoatmosphere may be performed without use of the exhaust fan 311 (see FIG.1).

However, as a whole the use of the described methods for enhancement inLMG co-production calls for an enhanced self-consumption of a power fordriving the up-graded MG compressor 405 or/and the additionallyinstalled exhaust gas compressor 314. A required amount of power may beextracted from the electric output 108 of the gas engine 101, resultingin a drastic increase in LP-LMG co-production rate at the sacrifice of amoderate and acceptable decrease in the GPG electric output. Another wayconsists in production of a required additional power by the steamturbine 207 through an increase in pressure, temperature and flow-rateof a steam generated in the bottoming cycle. For this purpose, a smallamount of an additional fuel is delivered via a pipe 110 into a ductburner 111 installed upstream of the waste heat recovery boiler 201.Production of an additional power in the steam bottoming cycle,resulting from supplementary firing of this fuel in the stream 109 ofthe hot and pressurized exhaust gas escaped the gas engine 101, ischaracterized by a very high fuel-to-power conversion efficiencyexceeding an efficiency of the gas engine and makes possible to enhancea LP-LMG co-production rate without decrease in the GPG plant electricoutput.

INDUSTRIAL APPLICABILITY

The performances of the reciprocating gas engine-based polygeneration(GPG) plant using the proposed method for exhaust waste energy recoveryare presented below in the tabulated and graphic forms. In the basicconfiguration the designed GPG plant is, for example, equipped with onesupercharged reciprocating gas engine and supplied with natural gas (NG)from the main pipeline. The most of delivered fuel is destined foron-site liquefaction, whereas the remainder is used as fuel for the saidengine. The engine is supplied with 15.1 kg/s of a charging airpressurized up to about 3.9 barA by the air compressor which consumesabout 2.6 MWe of electrical power. The engine produces about 9.7 MWe ofelectric power with fuel-to-power conversion efficiency of 46.3%. Thepressurized exhaust gases escape the engine cylinders at a pressure ofabout 3.6 barA and temperature of approximately T_(EXH-OUT)=535° C. Ahigh temperature part of waste thermal energy is used in the simplestone pressure level steam bottoming cycle with the a small-sizedpressurized waste heat recovery boiler and steam turbine producing about2.1 MWe of electrical output without supplementary firing of anadditional fuel.

In the basic GPG plant configuration the exhaust gas compressor is notused. Therefore, these gases are further cleaned, pre-cooled and usedfor an additional generation of about 0.8 MWe by the gas turbine withfollowing their converting into an effective refrigerant applied toliquefaction of the entire NG stream delivered into the GPG plant. ThisNG is delivered at a selected pressure of 60 barA and dehydrated in thepre-treatment package, wherein a CO₂ content in natural gas is usuallyalso reduced. However, taking into account a drastic increase in CO₂solubility in the pressurized LNG, a permissible CO₂ content in thenatural gas at the outlet of pre-treatment unit may be increased up to0.5-1.0% (v/v). Consequently, the CO₂ removal part of pre-treatment unitmay be minimized or even obviated. Therefore, in the basic GPG plantconfiguration the features required of a design of the NG pre-treatmentunit should correspond to a pressure of the co-produced LNG selected atthe level of 5.1 barA. The cleaned NG is further moderately pressurizedup to 80 barA by the NG compressor consuming only 0.08 MWe, then the NGis pre-cooled and fully liquefied in the gas liquefier. After two-stagedepressurization of the full liquefied natural gas stream and separationof the formed two-phase stream, the LP-LNG co-product at a rate ofG_(LNG)=˜4.2 ton/h is delivered to the customers at the rated pressureof 5.1 barA, whereas the gas vapor produced at a rate of ˜1.55 ton/h isused as gaseous fuel for the gas engine, providing ˜21 MWth of heatinput in the GPG plant. By this means 27% of all NG delivered into theGPG plant is converted into plant power output of W_(GPG)=9.9 MWe,whereas 73% of NG delivered is converted into LP-LNG co-product. A powerequivalent of this LNG co-produced may be estimated using equationproposed in the Tractebel 2015 report for WBG and resulting inW_(LNG)=(998.4−39.5×G_(LNG))×(G_(LNG)/1000)=3.5 MWe. With regard to theestimated W_(LNG) value the re-counted power output of the GPG plantadds up to W_(GPG-REC)=13.4 MWe, providing the total plant efficiency ata level of 63.8%.

At the described GPG plant, charging a modern large gas engine with thecombustion air is performed at a pressure of P_(AIR-IN)=˜4.0 barA. In sodoing, specific LNG co-production without consumption any power or anadditional fuel constitutes 0.43 ton/h per each MW of power generated bygas engine (GE). At the same time, the new gas engines with a muchhigher charging air pressure have been recently launched and are at theexperimental stands of the OEM companies. With supposition of theT_(EXH-OUT) data and fuel efficiency of the new engines, the conductedanalysis has revealed a strong positive impact of an increase in theP_(AIR-IN) value on improvement in the GPG plant performance as a wholeand on an increase in total and specific LNG co-production values inparticular. For example, an enhancement of the charging air pressure atthe inlet of described 10 MW gas engine up to 6 and 8 barA leads togrowing a specific LNG co-production at the GPG plant up to 0.61 and 0.7ton/MWh simultaneously with an increase in their total (re-counted)efficiency up to 69.6 and 72.1% correspondingly. In addition, theenhancement in a share of NG being liquefied at the GPG plant up to 79%and 82% may be achieved. By this means a further advancement in the gasengines development opens up also the promising prospects for asignificant improvement in the GPG technology performance as well. Theresults of comparative performance analysis of the GPG plants using abasic configuration with the gas engines having the different chargingair pressures are presented in the Table 1 and FIG. 3.

TABLE 1 P_(AIR-IN) = P_(AIR-IN) = P_(AIR-IN) = Parameter Unit 4barA6barA 8barA Gas engine output, W_(GE) MWe 9.73 9.73 9.73 Hourly fuelconsumption t/h 1.56 1.52 1.49 Gas engine fuel efficiency % 46.3 47.348.3 Exhaust gas temperature, T_(EXH-OUT) ° C. 535 555 575 Plantelectric output, W_(GPG) MWe 9.93 9.79 9.56 Plant electric efficiency %47.3 47.6 47.5 Pressure of NG delivered barA 60 60 60 High pressure ofNG liquefied barA 80 80 80 Low pressure of LNG co-product barA 5.1 5.15.1 Hourly LNG co-production t/h 4.2 5.9 6.8 A share of NG liquefied %72.9 79.5 82.0 Specific rate of LNG co-produced t/MWh 0.43 0.61 0.70Power equivalent of LNG co-product MWe 3.48 4.52 4.96 Re-counted plantoutput, W_(GPG-REC) MWe 13.41 14.31 14.52 Total plant efficiency % 63.869.6 72.1

The possible end-users of the invented method are characterized by awide diversity of an acceptable pressure of LNG co-product (P_(LNG)) anda required specific rate of LNG co-production. To meet the customerrequirements, the basic design of the GPG plant shown in FIG. 1 may besupplemented by the exhaust gas compressor providing an increase inexhaust gas pressure P_(GT-IN) at the gas turbine inlet and by the ductburner providing an increase in exhaust gas temperature T_(WHRB-IN) atthe waste heat recovery boiler inlet (see FIG. 2). Along with anoptional possibility for increase in NG pressure P_(HP-IN) at the gasliquefier inlet, all mentioned means make possible to customize the GPGplant configuration and provide the customer's demand for LNG co-productwithout reduction in electric output of the GPG plant. The parameters ofthe 10 MW GPG plant described above in the 6 plant optionalconfigurations have been calculated for the different combinations ofthe mentioned NG and exhaust gases pressures and temperatures in thewide ranges of their possible values: P_(LNG)=1.05÷11 barA,P_(GT-IN)=3.5÷11.6 barA, T_(WHRB-IN)=535÷695° C. and P_(HP-IN)=60÷200barA. The results of these calculations are presented below in the Table2.

TABLE 2 Conf. GPG plant configuration features 1 2 3 4 5 6 Pressure ofLNG co-product barA 1.05 1.05 5.1 11.0 11.0 11.0 Exhaust pressure at GTinlet barA 3.5 6.9 6.9 9.9 11.6 11.6 NG pressure at liquefier inlet barA80 60 80 100 120 200 Exhaust temperature at WHRB inlet ° C. 535 615 595645 680 695 GPG plant parameter Unit GPG plant power output MWe 9.729.77 9.81 9.78 9.74 9.68 Hourly fuel consumption by DB t/h 0 0.11 0.080.15 0.20 0.22 Hourly feel consumption by GPG plant t/h 1.56 1.67 1.641.71 1.76 1.78 Total heat input with NG fuel MWth 21.01 22.52 22.1323.06 23.74 24.03 Hourly LNG co-production at GPG plant t/h 3.70 5.366.60 8.40 10.08 12.06 A share of NG liquefied at GPG plant % 70.4 76.380.1 83.1 85.2 87.1 Specific rate of LNG co-produced t/MWh 0.38 0.550.67 0.86 1.04 1.25 Annual LNG co-production at GPG plant kton/y 30.844.6 54.9 69.9 83.9 100.4 Specific power consumed at SS LNG plants kWh/t852 787 738 667 600 522 Fuel self-consumed in LNG production: at SS LNGplant % 17.9 16.7 15.8 14.5 13.3 11.8 at GPG plant % 0 2 1.2 1.8 2.0 1.8Power equivalent of LNG co-product MWe 3.15 4.22 4.87 5.60 6.05 6.30Re-counted GPG plant output, W_(GPG-REC) MWe 12.87 13.99 14.68 15.3815.79 15.98 Total GPG plant efficiency % 61.2 62.1 66.3 66.7 66.5 66.5

The graphical presentation of the calculation results is shown if theFIG. 4-6. As evident from the FIGS. 4 and 5, an increase in the exhaustgases pressure at the gas turbine inlet and the HP NG gas at the gasliquefier inlet together with an increase in pressure of the LNGco-product make possible to enhance an LNG co-production capacity in theplant configurations No. 5 and 6 up to G_(LNG)=10-12 t/h (that is by afactor of 2.7-3.3) simultaneously with an increase in the re-counted(total) GPG plant efficiency from η_(REC)=61.2% up to η_(REC)=66.5%.This is accompanied by a growing of a share of NG being liquefied at theGPG plant from 70.4% up to 85.2-87.1%. The mentioned results may beachieved without reduction in electric output of the GPG plant onlythrough very efficient supplementary firing of a small amount of anadditional fuel in the stream of hot exhaust gases escaped the gasengine. As evident from the FIG. 6, a self-consumption of fuel for LNGco-production at the GPG plant (if needed) does not exceedg_(SC)=1.2-2.0%, which is several times less than an amount of fuelself-consumed at the conventional mini and small-scale LNG plantscomparable to the GPG plant in annual LNG capacity.

Application of the GPG technology for driving the refrigerationcompressors and producing an extra LNG at the LNG plant may also be verypromising, especially at the micro and mini-scale LNG facilities. The N2expander technology is usually used at these plants for the LNGproduction, resulting in simplification of their design butsignificantly increasing an energy intensity of the liquefactionprocess. The results of comparative analysis of two approaches to energysupply of the mini-scale LNG plant are presented in the Table 3 and FIG.7.

TABLE 3 Prime mover at the LNG plant SC gas Gas LNG plant features andparameters Unit turbine engine + GPG Electric power of prime mover kW3,515 3,706 Electric efficiency of prime mover % 27.9 47.5 Fuel consumedby prime mover t/h 0.93 0.58 Main NG lquefaction technology N₂ expandercycle at P_(LNG) = 1.05barA Specific power consumed by expander cyclekWh/t 835 835 LNG produced with use of expander cycle t/h 4.21 4.44 Fuelself-consumed in expander cycle % 18.1 11.5 Use of GPG technology no yesSpecific extra LNG co-production rate kg/kWh n/a 0.55 Extra LNGco-production t/h n/a 2.04 Increase in LNG co-production % n/a 48.4Total hourly LNG production t/h 4.21 6.48 Annual LNG production at 8322h/y MTPA 0.035 0.054 Extra feel consumed by GPG t/h n/a 0.042 Fuelself-consumed in extra LNG production % n/a 2.0 Re-counted fuelself-consumed at LNG plant % n/a 8.7 Re-counted specific power consumedkWh/t n/a 572

Here the mini-scale LNG plant is exemplified by a facility producing 4.2ton/h of LNG (˜35 kton/y) at a pressure of 1.05 barA and consuming ˜3.5MW of power from its own prime mover. A small gas turbine has beenselected as such mover for the first variant of the LNG plant powersupply. A high specific power consumed in the small-scale N₂ expandercycle (835 kWh/ton) and a low fuel-to-power conversion efficiency(27.9%) of the GT lead to a high amount of fuel self-consumed (18.1%) atthe plant. This first power supply variant is compared with theapplication of gas engine (GE)-based GPG technology, wherein 3.7 MW gasengine is used as a prime mover at the LNG plant. The LNG co-productionin this technology is moderately enhanced up to 0.55 t/MWh using themeasures described previously for the configuration No. 2 of the GPGplant in the Table 2. The second variant of power supply makes possibleto reduce a fuel self-consumption in generating a power required for theN2 expander cycle down to 11.5%, resulting from a much higherfuel-to-power conversion efficiency (47.5%) of the GE only. In addition,this variant provides generation of an extra LNG product at a rate of ˜2ton/h, resulting in augmentation of plant LNG capacity by 48.4%. Since afuel self-consumption in production of the extra LNG does not exceed 2%,total fuel self-consumption at the LNG plant using GPG technology may bereduced down to 8.7%. Finally, the mentioned increase of LNG capacity byalmost 50% is achieved without installation of an additional specializedrefrigeration equipment and calls only for increasing a capacity of theNG pre-treatment unit and harnessing the gas liquefier in its simplifieddesign.

It should be noted that the term “comprising” does not exclude otherelements or steps and “a” or “an” do not exclude a plurality. It shouldalso be noted that reference signs in the claims should not apparent toone of skill in the art that many changes and modifications can beeffected to the above embodiments while remaining within the spirit andscope of the present invention.

What is claimed as new is:
 1. A method for an exhaust waste energyrecovery at a reciprocating gas engine-based polygeneration plant,comprising in combination: supplying said polygeneration plant with amethaneous gas selected from a group consisting of pipeline natural gas,biogas, landfill gas, coal-bed methane and renewable methane and used asa fuel in said gas engine; supplying the gas engine with a charging airpressurized by an air compressor and cooled upstream of the gas engine;burning a mixture of the fuel and the charging air in the gas enginewith producing a gas engine power output, as a main product of thepolygeneration plant, and releasing a pressurized exhaust gas streamcomprising a mixture of nitrogen, oxygen, carbon dioxide and water vaporat a high temperature; harnessing most of a hot thermal energy of thepressurized exhaust gas for production of a process steam in a wasteheat recovery boiler installed at an outlet of the gas engine; using theprocess steam for production of a power output of a steam bottomingcycle; expanding the pressurized exhaust gas in a gas turbine installeddownstream of said waste heat recovery boiler, resulting in recovering akinetic energy and a remainder of a thermal energy of the pressurizedexhaust gas for production of a power output of said gas turbine; usingat least a part of the power outputs of said gas turbine and said steambottoming cycle for driving said air compressor; and additionallycomprising: supplying the polygeneration plant with said methaneous gasat a rate exceeding an amount of said fuel used by the gas engine;forming a pre-treated methaneous gas stream through drying and purifyinga supplied methaneous gas as needed to meet a pre-treatment qualitystandard set up for the methaneous gas being liquefied; compressing thepre-treated methaneous gas up to a high pressure of at least 60 barA bya methaneous gas compressor if necessary, resulting in forming ahigh-pressure methaneous gas stream; pre-cooling said high-pressuremethaneous gas so, forming a pre-cooled high-pressure methaneous gasstream; reducing in temperature of the pressurized exhaust gas escapedthe waste heat recovery boiler to a near ambient value with accompanieddrainage of a formed condensate; drying the pressurized exhaust gas andfollowing pre-cooling a dried pressurized exhaust gas to a temperaturebelow 0° C. in a cold regenerator so, forming a dried and pre-cooledpressurized exhaust gas stream upstream of said gas turbine; saidexpanding of the dried and pre-cooled pressurized exhaust gas in the gasturbine, resulting in producing the power output by said gas turbine andforming a deeply cooled non-pressurized exhaust gas stream escaped thegas turbine; recovering a cold thermal energy of said deeply coolednon-pressurized exhaust gas first for a liquefying of the whole of saidpre-cooled high-pressure methaneous gas in a gas liquefier and then forsaid pre-cooling of the dried pressurized exhaust gas in said coldregenerator; using a non-pressurized exhaust gas removed from the coldregenerator to an atmosphere for removing a water vapor captured duringsaid drying of the pressurized exhaust gas; depressurizing ahigh-pressure liquefied methaneous gas escaped the said gas liquefierdown to a selected low pressure, resulting in forming a low-pressuretwo-phase liquefied methaneous gas stream; separating said low-pressuretwo-phase liquefied methaneous gas stream, resulting in forming alow-pressure methaneous vapor stream and a low-pressure liquefiedmethaneous gas stream; using said low-pressure methaneous vapor as thefuel for the gas engine; using said low-pressure liquefied methaneousgas as a co-product of the polygeneration plant; and using a part of thepower outputs of the gas turbine and the steam bottoming cycle fordriving said methaneous gas compressor.
 2. A method as in claim 1,wherein depressurizing the high-pressure liquefied methaneous gas isperformed sequentially first in a work-performing liquefied methaneousgas expander so that a medium-pressure liquefied methaneous gas isformed and then in a Joule-Thompson valve.
 3. A method as in claim 2,wherein a cold thermal energy of the low-pressure methaneous vapor isrecovered first for subcooling said medium-pressure liquefied methaneousgas upstream of the Joule-Thompson valve, and then for said pre-coolingof the high-pressure methaneous gas upstream of said gas liquefier.
 4. Amethod as in claim 1, wherein a pressure of the low-pressure methaneousvapor upstream of the gas engine is provided at a level exceeding apressure of the charging air through said selecting of the low pressureof said two-phase liquefied methaneous gas stream or/and compressing thelow-pressure methaneous vapor if necessary.
 5. A method as in claim 1,wherein said drying of the pressurized exhaust gas is performed by apressure swing adsorber, wherein said non-pressurized exhaust gasoutgoing from the cold regenerator is used for purging a regenerated bedof said pressure swing adsorber.
 6. A method as in claim 5, whereinremoving the non-pressurized exhaust gas from the pressure swingadsorber to the atmosphere is performed by an exhaust fan consuming apart of the power outputs of the gas turbine and the steam bottomingcycle.
 7. A method as in claim 1, wherein an enhanced yield of thepolygeneration plant co-product is achieved through an increase in apressure of the high-pressure methaneous gas at an outlet of themethaneous gas compressor up to a value exceeding 60 barA.
 8. A methodas in claim 1, wherein an enhanced yield of the polygeneration plantco-product at a given pressure of the charging air is achieved throughan increase in a pressure of the dried and pre-cooled pressurizedexhaust gas at an inlet of the gas turbine, resulting in producing anextra power output by said gas turbine and in additional reducing atemperature of the deeply cooled non-pressurized exhaust gas streamescaped the gas turbine.
 9. A method as in claims 5 and 8, wherein saidincrease in the pressure of the dried and pre-cooled pressurized exhaustgas is performed with use of an exhaust gas compressor installedupstream of the pressure swing adsorber and equipped with anaftercooler.
 10. A method as in claims 7-9, wherein an extra poweroutput of the steam bottoming cycle is provided through supplementaryfiring an additional fuel in the stream of the pressurized exhaust gasahead of the waste heat recovery boiler.
 11. A method as in claims 7-10,wherein said extra power outputs of the steam bottoming cycle and thegas turbine are consumed for driving said exhaust gas compressor and forserving the needs of the methaneous gas compressor for a higher powerinput.